June 24, 2005 British Columbia Utilities Commission Sixth Floor - 900 Howe Street Vancouver, BC V6Z 2N3 Attention: Mr. Robert J. Pellatt, Commission Secretary Dear Sir: Re: Terasen Gas Inc. (“Terasen Gas”)

Application for Approval of Transactions with respect to Southern Crossing Pipeline (“SCP”) and Inland Pacific Connector (“IPC”) Commission Staff Request

Terasen Gas submitted to the British Columbia Utilities Commission (the “Commission”), its application for approval of certain transactions with respect to SCP and IPC on June 1, 2005. Subsequently, Commission staff requested that Terasen Gas submit a copy of a prior application it had submitted on December 5, 2002, which was referenced in the June 1, 2005 submission. The December 5, 2002 Application was submitted in a Confidential manner, in recognition of the sensitive commercial nature of the arrangements with third parties, as set out in that application. Accordingly, Commission staff also asked Terasen Gas to identify any portions of the December 5, 2002 submission that should continue to be kept confidential, in the event the Commission distributed that document to stakeholders. Attached is an electronic copy of the December 5, 2002 Application in its entirety. Terasen Gas has discussed the Commission request with Northwest Natural Gas Company (“NWN”), party to an agreement included in the December 5, 2002 Application. Terasen Gas and NWN are in agreement that, although it was justified to have the application kept confidential when filed, as approximately three years have passed the commercial sensitivity has diminished. As a result, Terasen Gas submits that it does not require any portions of the December 5, 2002 submission to be kept confidential. We trust the Commission finds this in order. Should you have any questions with respect to this application, please contact Tom Loski at (604) 592-7464. Yours truly, TERASEN GAS INC. Original signed by Tom Loski

For: Scott A. Thomson Attachments

Scott A. ThomsonVice President, Finance & Regulatory Affairs 16705 Fraser Highway Surrey, B.C. V3S 2X7 Tel: (604) 592-7784 Fax: (604) 592-7890 Email: scott.thomson@terasengas.com www.terasengas.com

B-2

DC Gas Utility Ltt..16705 Fraser HighwaySurrey, British ColumbiaV3S 2X7

~ ~"~f!J~~;(;i!~AAm\( V .;i\f!!i1eti"'lJ;r~ri9~iZ:VVL.

BC Gas'" ,CQNFID E~L

British Columbia Utilities Commission6th Floor, 900 Howe StreetVancouver, B. C.V6Z 2N3

Attn: Mr. R. J. Pellatt, Commission Secretary

Dear Sirs/Madams:

Re: Consent to Termination of the PG&E Southern Crossing Pipeline Transport andPeaking A gr eements effective January 1, 2003 and associated arrangements

---'" --

BC Gas Utility Ltd. ("BC Gas") proposes to tenninate the existing PG&E Southern Crossingtransport and peaking contracts effective jan~ 1,2003 and to enter into a new firmtransportation service agreement with Northwest Natural Gas Company ("NWN") effectiveNovember 1,2004. In addition, BC Gas also proposes to take assignment of 53,500 MMcf/dof Nova/ANG capacity fromPG&E effective January 1, 2003, withre~signment of 47,500MMcf/d to NWN effective November 1,2004. .-

,

Attached is the full proposal, , including attachment of supporting economic analysis. BC Gasis seeking approval of the arrangements summarized in paragraphs I to 10 of the executivesummary in the proposal. BC Gas requests BCUC consent as early as possible.

Copies of the proposed agreements between BC Gas, PG&E and NWN are also attached. Inrecognition of the commercial nature of these agreements, BC Gas requests that they be keptco~dential.

Yours truly,

~t~~jt~~~~-~ D. D. Kellmann..7 ~Director, Financial Development Services

DDKlKBM

Attach.

Commission-8243

CONFIDENTIAL

Executive Summary

BCGUL and BCGI have put in place arrangements whereby existing Southern CrossingPipeline (SCP) capacity will be used to provide NW Natural with firm transportation servicefrom Yahk to Huntingdon beginning November 2004. The service will be provided usingSCP capacity that is currently contracted by PG&E Energy Trading Canada (PG&E). Thearrangements will reduce BC Gas's exposure to PG&E's current financial situation, capitaliseon the marketing and developmlent efforts of the Inland Pacific Connector project andincrease the value of the SCP capacity with a net benefit accruing to BC Gas's customers.

BCGUL is seeking approval for the proposed arrangements:

1. BCGUL and PG&E agree to terminate the existing PG&E SCP Transportation Agreementand the PG&E Peaking Gas Agreement effective January 1, 2003. BCGUL will then havecontrol of the SCP capacity.

2. BCGUL will take assignment of 53.5 mmcfd of TCPL (NovajANG) capacity from PG&Eeffective January 1, 2003 allov'/ing BCGUL to access the full direct gas flow path from theAlberta supply hub to the Hunl:ingdon market hub.

3 As part of 1 and 2 above BCGiUL will make an ongoing payment to PG&E in recognitionof the early release of the SCP capacity to BCGUL and the assignment of PG&Es' TCPLcapacity to BCGUL. This payment will be to the sole benefit of PG&E Energy Trading.

4. BCGUL will hold the SCP anal TCPL capacity for the period from January 1, 2003 toNovember 1, 2004 and will o~)timize the value of the capacity by meeting the potentialpeaking needs of its core customers and by mitigating the capacity with buy and selltransactions and assignments 'with third party shippers over that time frame.

5. BCGI has held discussions and executed a letter agreement with Northwest Natural GasCompany ("NWN") whereby NWN will contract with BCGI for 46.5 MMcfd of firmtransportation service using ~,CP capacity released by PG&E, effective November 01,2004 to match the transport I:apacity requirements NWN requested in response to theInland Pacific Connector Project ("IPC") open season. As part of these arrangements,BCGI has committed to rele;~se NWN from any ongoing obligations to contract forcapacity on IPC.

6. BCGI has reached agreement with PG&E and NWN to make BCGUL the counterparty forthe transactions outlined above. BCGUL and NWN will enter into a 16 year firmtransportation agreement utilizing 46.5 MMcfd of the Southern Crossing capacity andtake assignment of 47.5 MMc1:d of the TCPL capacity effective November 1, 2004. Thedemand charges paid by NWr'l1 significantly exceed the current SCP tolls paid by PG&E,and also locks the value in IIDng term. In the short to medium term, the demand

Page 1

charges exceed the current market value of the capacity I however they do reflect thecosts NWN would have expect,:d to pay as an IPC Shipper.

7.

r-- , development efforts carried out to date on IPCby BCGI, has resulted in a significant long term value for BCGUL customers, asevidenced by the arrangements negotiated with NWN. With the transfer of NWN frombeing an anchor tenant on IPC to contracting for existing SCP capacity, BCGULshareholders are now at increased risk that IPC will be further deferred or cancelled.BCGUL's intent is to begin recovery of IPC costs in 2006 if the project has not

proceeded.

8. BCGUL will continue to hold the remaining 6.0 MMcfd of TCPL and SCP capacity currentlyheld by PG&E after November 1, 2004 either to serve the needs of core marketcustomers or to be marketed to third parties.

9. BCGUL will put in place alternate peaking gas arrangements as required to replace thePG&E Peaking Gas Agreement, to the benefit of the core market customers effectiveNovember 2004. BCGUL has undertaken analysis on peaking options and hasdetermined that Mist storage expansion capacity available November 2004 to be offeredon a long term basis appears to be the best replacement for the peaking contract. BCGas will enter into discussions with NWN early in 2003.

10. In recognition of the additional value that will be delivered by the NW Naturalarrangements, BCGUL and BC(:;I also agree the following:.BCGI has no ongoing rights or obligations with respect to the SCP capacity released

by PG&E effective January 1, 2003; and.BCGUL will accept assignm,ent from BCGI of any SCP capacity that BC Hydro may put

to BCGI in the period November 1, 2004 to October 31, 2010.

There is no new capital investment associated with these arrangements, however BC GasUtility is expected to realise a minimum increase in net revenues associated with the SCPcapacity of $2.7 million per annum beginning in 2004. The net present value of thesearrangements to BCGUL is expecl:ed to be between $20 to $35 million based on the fixedrevenue streams contracted and accounting for BCGI recovery of IPC development costs.The proposed transactions are in the interest of BCGUL and its customers in maximisingcurrent and future value and redut:ing the risk of non recovery of SCP revenues.

Page 2

Discussion

1. Southern Crossing Pipelinle Project

1.1 Description

BCGUL first applied to the BCUC for a CPCN for the Southern Crossing Pipeline Project inMay 1997. Following a public hearing, the BCUC denied the application, however allowedBCGUL to reapply if it could put irl place arrangements to help mitigate the cost to the corecustomers. In particular the BCUC: proposed that BCGUL work with BC Hydro to realise anysynergies between BC Hydro's 1:hermal generation requirements and the new pipelineproposal.

Subsequently, BCGUL began disc:ussions with BC Hydro, and also held an open seasonoffering qualified parties to bid for firm transportation service from Yahk to Huntingdon. Asa result BCGUL was able to put in place long term transport arrangements and matchingpeaking gas agreements with bol:h BC Hydro and PG&E Energy Trading Canada, each forcapacity of 52.5 mmcfd. In total, the third party contract capacity of 105 mmcfd resultedin annual revenue of $7.2 million per year for 10 years with unilateral shipper renewal rightsfor up to another 10 years.

Before agreeing to put these arrangements in place, BC Hydro required BCGI to accept anoption that would allow BC Hydro 'to put the capacity to BCGI for the remaining period in theprimary term (ie up to October 31, 2010) if it decided it no longer required the capacity.

BCGUL re-applied for a CPCN in December 1998, and after a second public hearing process,the BCUC granted the CPCN in MclY 1999. In the decision, the CPCN was approved basedon SCP offering the highest bene1'its to ratepayers over the long run in part helped by theprovision of firm third party reVenlJeS of $7.2 million provided by BC Hydro and PG&E.

1.2 Current Valuation of SCP ~=apacitv

SCP capacity has provided signif'icant value to core customers over the last two yearsprimarily during the winter of 2000/01. Although commodity prices remain strong the netvalue of pipeline capacity in both the cash market and forward markets do not recovercosts. Limited cost recovery on pipeline assets in the forward markets is the case on mostNorth American transport today. This is due to reduced demand in the consumptionregions and a corresponding redulced supply position in the producing regions resulting intight supply/demand but with under-utilized or non-constrained pipeline capacity. The valueof pipeline capacity will improve ~,hen regional and N.A. demand recovers due to economicrecovery or strong weather related demand.

The SCP capacity held by the current SCP shippers is backed up with TCPL capacity toprovide access to AECO sourced supplies. When evaluating the benefit of SCP capacity theinclusion of matching TCPL capacity is required to determine the value of delivering AECOpriced gas to the Sumas market. The forward markets today provide about 85% recoveryof SCP/TCPL demand charges on an annual basis. As comparison, the forward marketsprovide about 80% recovery of WEI T -South long haul capacity (see attachment 2 fordetailed calculations). As T -South capacity is not trading at full value on forward marketsmany counterparties decided to not re-contract some or all of their T -South capacity inSeptember. The shippers who continue to hold T -South capacity including BCGUL have

Page 3

determined that holding capacit)1 provides pricing diversity and protection from anotherprice disconnect in the market in I:he future. Conversely, producers and marketers who holdcapacity gain the opportunity to !~arner the premiums that will accrue in later years on thepipelines.

If BCGUL were to attempt to market the PG&E capacity today due to PG&E default in theabsence of having gone through the analysis, costs and marketing of IPC, BCGUL would notbe able to capture the value that NWN has agreed to provide. Based on today's marketBCGUL would be fortunate to find an SCP shipper willing to pay the existing SCP tolls of$0.188jGJ let alone the $0.43j$0.53jGJ NWN has agreed to compensate for IPC long term.NWN will pay these tolls because it was in agreement that new infrastructure is needed intothe region to meet future demand and that the risk of another Sumas price disconnect ishigh until added capacity is in place. Without the IPC development and marketing efforts,BCGUL would not have created any of the $20-$30 million NPV it is looking at today.

2. Northwest Natural Gas C(tmpany

2.1 Description

NW Natural ("NWN") is a natural gas distribution company based in Portland Oregon,serving approximately 520,000 c:ustomers. The company accesses approximately 105mmcfd of their firm gas requiremlents at the Sumas market hub, and have been seeking toput in place firm upstream transportation arrangements to connect back to the supplyareas. They recently put in plac:e an arrangement with a third party for T -South capacity,and expected the Inland Pacific Connector project to provide them with firm transportationback to Alberta supply for the remainder of their requirements.

BCGI has had active discussions with NWN with respect to the Inland Pacific Connectorproject, and NWN submitted a bidlding commitment to contract for Yahk to Huntingdon firmtransportation service on IPC during the Open Season in May 2001. When the IPC projectwas deferred from 2003 to 2004, NWN continued to support the project, and put in placeshort term arrangements to bridge the gap. They are now seeking to put in place transportarrangements for 2004 and beyond.

The downturn in the North Americ:an economy, the credit crunch in the energy market, andthe deferral and/or cancellation of many planned power generation projects has alsoresulted in decision to further defer IPC until 2005. At the same time, PG&E's financialsituation presents an opportunity to use existing SCP capacity to serve NW Natural's

requirements.

With these arrangements, BCGI vlill forego future revenue that would have accrued to IPCand loss of an anchor tenant may also result in further deferral of the in-service date of IPC.As a result BCGUL (and BCGI) arE! requesting recovery of the IPC development costs in theevent the decision is made to terminate the project.

Page 4

2.2 NW Natural Contractual J~rrangements

BCGUL will enter into a transportcltion agreement with NWN for firm non-recallable and non-curtailable capacity from Yahk to Huntingdon upon accepting transfer of the arrangementsput in place by BCGI. The principal terms are as follows:.16 year term from November 2004 to October 2020.Contract Capacity of 46.5 mmcfd.Annual demand charges

0 Contract Years 1-6 $7.3 million (approximately $0.43jmcf)0 Contract Years 7-16 $9.0 million (approximately $0.53jmcf)

.In the event that Southern Crossing is expanded and the Inland Pacific Connectorproject proceeds, the demand charges are increased to match IPC tolls, up to an agreedcap (initially $0.53jmcf, and then $0.61jmcf in 2010)

.Permanent assignment of 47 .~; mmcfd of TCPL ANGjNOVA capacity

The NWN transport agreement provides for firm transportation using the SCP capacityreleased by PG&E. As BCGUL willi not retain any curtailment rights, BCGUL will have to putin place, as required, alternate peaking arrangements (Refer to Attachment 4.)

As discussed in section 1.2, the demand charges that NWN have agreed to pay over thelong term exceed the current market valuation of the TCPLjSCP transportation path. Thecharges do however reflect a di~;count to the tolls NWN was expecting to pay as an IPCshipper, assuming the market supported the need for incremental capacity. The ability torealise a market premium is directly related to the marketing and development efforts ofIPC.

3. PG&E Energy Trading, Calnada

3.1 Description

PG&E Energy Trading, Canada is a subsidiary of PG&E National Energy Group ("NEG"), an

integrated energy company ~/ith operations that include power generation anddevelopment, natural gas transrnission and wholesale energy marketing and trading inNorth America. PG&E National Energy Group's parent company PG&E Corp also owns PacificGas and Electric Company, the electric and gas utility serving Northern and centralCalifornia. The utility was one of the early casualties of the California "Energy Crisis", andalthough still operating, declared bankruptcy in late 2001.

NEG has not been immune from the current financial crisis being experienced by many ofthe major North American integrated energy companies such as Mirant, Wililiams, and EIPaso. Although NEG's Pacific Gas Transmission asset remains a viable asset, its exposure tomerchant generation and energy t:rading has brought the group to the brink of bankruptcy.

At the time the SCP agreements were executed, PG&E Corp had investment grade credit.Over the last few months this has deteriorated quickly, and in November NEG began todefault on its debt repayments. This raises serious concerns as to the security of therevenue stream from PG&E and the potential negative consequences of a failure by PG&E onBCGUL and its customers.

Page 5

If PG&E defaults on its obligations to BCGUL, it will cease to pay the $3.6 million per year indemand charges and BCGUL's clJstomers will be at risk for the subsequent shortfall inrevenue. BCGUL would take step~5 to mitigate the negative impact on a day to day and along term basis but these efforts I:ould be frustrated by the lack of upstream transportationcapacity as PG&E holds the TransCanada Pipelines (TCPL) capacity back to the Albertasupply hub. In the event of a PI:;&E bankruptcy, BCGUL's access to the SCP capacity andthe TCPL capacity may also be hampered by the actions of other creditors or the receiversuch that mitigation of the revenue shortfall is not possible.

To mitigate this risk, BC Gas has negotiated with PG&E to take back the SCP capacity andthe associated upstream TCPL ca~lacity so that it is available to contract long term to NWN.Although NWN does not require thle capacity until November 2004, BCGUL believes that it isprudent to take the capacity effective immediately. BCGUL will then implement amitigation plan to offset any lost rlevenues until November 2004. (See Attachment 1).

3.2 Determination of PG&E TE!rmination Payments

BCGUL initially negotiated an anrlual fee to pay PG&E for releasing the SCP capacity andassigning the associated TCPL capacity as of November 2004. As events unfolded, it wasdecided that the BCGUL should acquire the capacity as soon as was practicable to avoid anychance that a PG&E bankruptc:y could put the NW Natural arrangements at risk.Subsequently the payments were reduced in recognition of the current market value of theSCP and TCPL capacity between Jclnuary 1, 2003 and November 1, 2004.

Contract Years

Years 1-6Years 7-16

Initiall

Paymel!}.L$1,200,O..QQ-$~.QQQ

TCPLAdjustment($150,000)($150,000)

NetPayment

$825,000$14~,~00

SCP

Adjustment($225,000)($225,000)

I

PV @ ~,__2002 (7% discount factor) $4.2 million$2.8 million

I

PV @ Jan 1, 2002 (15% discount factor)

PG&E also requested the ability to monetise the payment stream, at their option, using a15% discount factor. As BCGUL's marginal cost of debt is much less than 15%, if PG&E

Page 6

exercises this option there will be an additional net benefit flowing back to BCGULcustomers.

4. BC Hydro SCP Capacity

BC Hydro contracted for SCP on the basis of its expected requirements for Burrard Thermaland two gas fired generation projects on Vancouver Island proposed to be in service by2002. One of these plants is in service; however the second has now been delayed pendinga review by the BCUC, and the approval of the associated gas pipeline (Georgia StraitCrossing). At this point, it is expected that the earliest that these projects could be inservice is third quarter 2006 if at all. The new Energy Policy announced by the BCGovernment on November 25, als:o puts in question the long term operation of the BurrardThermal plant.

These developments increase the risk that BC Hydro may opt to put the SCP capacity toBCGI before the end of the primcJry term and as early as November 2004. In this event,BCGUL is in the best position to mitigate lost revenues from the capacity by using it to helpservice the firm and peaking requirements of its customers or through buy and selltransactions and assignments with third party shippers.

An analysis of this risk is inclulded in Attachment 2. Although recovery would varysignificantly from year to year it is expected that over the remaining period in the primaryterm (eg Nov 2004 to 2010), BCGUL would on average fully recover the demand chargesthat it would have otherwise reoeived from BC Hydro. Based on today's relatively weakbasis differentials calculated from current forwards, BCGUL would still recover $2.6 millionof the $3.6 million it otherwise would expect to recover from BC Hydro.

If BCGUL is able to replace T -South long haul capacity with SCP(BCH) and TCPL capacity inthe core portfolio, core customer:5 will have a positive benefit. These two flow paths areshowing the same net value today and are expected to move in concert as marketdifferentials change. The added benefits of AECO sourcing versus Station#2 for the coreportfolio include better diversity" reduced pressure at Station#2 and more contractingoptions that when combined provi,je considerable additional upside.

Any potential annual deficit will more than be made up by the increased revenue that will beobtained from the NWN firm service arrangements (Refer to Attachment 3).

S. Inland Pacific Connector

BC Gas has been developing th,e Inland Pacific Connector project as a solution to theconstrained market place at SumalsfHuntingdon. NWN has been an active supporter of IPC,and made a binding commitment to contract for IPC capacity during the Open Seasonprocess in May 2001.

Spent and committed IPC development costs to the end of 2002 amount to approximately$5.0 million. Planned expenditures to April 2003 increase this amount to $5.6 million tocomplete the current stage of development. At this point, these costs are being accrued ina separate account and have not been included in BCGUL's revenue requirements.

The current proposed in-service (jate for the project is November 2005, however withoutNWN as an anchor tenant, it is expected this will be deferred at least to November 2006. It

Page 7

is proposed that in the event the project does not proceed by 2006, that BCGI be allowed torecover these development costs iin recognition of the following factors:.Development and marketing of IPC help to increase the market value of long term SCP

Capacity.NWN being available to contract for the PG&E as a result of its support of IPC.Release of NWN from any and all obligations to contract for capacity on IPC

6. Financial Impacts

The net benefits that would flow to BCGUL's customers are summarised in the proformashown in Attachment 3. In the B,3se Case it is expected that the net revenues will increaseby at least $2.6 million per annum over the current arrangements, and the net NPV of thearrangements are in excess of $20 million depending on the degree IPC development costsare recovered.

BCGUL customers will realize very' significant long term financial benefits over the projectedbenefits of the existing SCP arrangements. This is a direct result of the development workon the IPC projects and assignment of the NWN IPC commitment to the available SCPcapacity. It is reasonable that BCGUL shareholders recover the IPC development costs as aresult of this value transfer. BCC,UL shareholders have increased the risk that IPC will bedelayed or even cancelled as a res;ult of this value transfer to BCGUL customers.

Page 8

Attachment 1

Mitigation of SCP and TCF-L Capacity to Nov 2004

In order to ensure that BCGUL will be able to complete the assignment of 46,500 MMcfjd ofthe PG&E SCP transportation capacity to Northwest Natural effective November 01, 2004BCGUL will take back all of the PG&E transport and peaking capacity effective January 01,2003. BCGUL proposes to assume assignment of both the SCP and NovajANG transportcontracts as temporary replacement of the PG&E peaking obligations for the period January2003 to October 2004. Effective November 2004, BCGUL will replace the peaking contractwith new peaking assets designed to minimize overall costs for core customers.

Cost/Benefit of capacity for c,ore customers for the period January 2003 throughOctober 2004:

The table below shows that the incremental demand charges and forecast mitigationrevenues over the period Jan O~~ through Oct 04. The $14.7 million of added Demandcharges are forecast to be recoveired within $1.3 million based on the PG&E credit, currentforward basis spreads and impro'led peaking call price. In a high demand, highly volatileprice period the incremental benefits would be much higher. Summary calculations areattached for each cost component identified below.

The TCPL and SCP T -south spreads are highly volatile with actual recovery dependant onmarket conditions that generate the spreads at the time. BCGUL plans to mitigate the risksof mitigation recovery by locking in a portion of forward value prior to the period start.BCGUL will utilize both the SCP alnd TCPL capacity as core portfolio assets and as such willoptimize the peaking call price as peaking demand is required for core, including optimizingthe available mitigation when not required for core customers.

BCGUL proposes to add the SCP capacity mitigation recovery including all profit revenuesfrom flows on the assigned SCP capacity as well as revenues generated on the associated T-South as part of the current SCP margin recovery account. BC Gas proposes to create anew and separate gas supply iincentive plan to account for recovery of the assignedNova/ ANG capacity directed to maximize recovery of this capacity prior to re-assignment toa third party November 2004. BCGUL proposes sharing of 5% of all mitigation netrecoveries up to $0.5 million BC<;UL sharing and then 1.25% sharing thereafter over theassignment period. For example!, the forecast $7.5 million mitigation recovery from thetable above would generate $0.375 million in BCGUL sharing over the period. This incentive

Page 9

proposal is consistent with the mechanism under the existing GSMIP program and will notresult in BCGUL ability to prioriti;~e NovajANG recovery to BCGU's benefit and will continueto reward BCGUL to reduce cost for core customers overall.

Page 10

Attachment 2 -

Mitigation of BC HydrlQ SCP Capacity

BC Hydro has a put option on the! SCP contracts back to BCGI with 13 months notice to thenext renewal date effective ever,,' November 01. For example, the earliest BC Hydro couldput the capacity back to BCGI i~; November 2004 with notice required by September 30,2003. If BC Hydro exercises the put BCGUL wants confirmation it can take assignment ofthe contracts from BCGI and that BCGI has the option to assign the SCP contracts to BCGULto meet firm customer requirements. BCGUL will then re-assign the capacity to a thirdparty or maintain the capacity within the core portfolio based on optimizing return onassets. If maintained in the cort~ portfolio BCGUL will continue to assume peaking supplysourcing back to AECO and will mitigate the capacity for the remaining year.

Although the SCP capacity would achieve benefits on its own it is likely that BCGUL wouldmatch any BC Hydro put-back with corresponding NovajANG capacity to achieve the AECOsourcing liquidity and price benefi'ts that SCP provides opportunity for. Based on the currentforward market, the mitigation an,d peaking benefits available to BCGUL to recover the costsof the BC Hydro SCP capacity $7.4 million of the total $8.8 million SCP and TCPL transportdemand charges. In a cold wint,er BCGUL would achieve close to 200% recovery and theminimum recovery in a warm winter would be 50% of demand costs. Over time BCGULexpects to recover close to full co~;ts of the capacity as illustrated in the table below.

BCGUL will also have the option to utilize the 53.5 MMCFjd of SCPjTCPL contracts as abaseload supply option versus the peaking option outlined above. This may be added to theportfolio as baseload sourcing but: would likely in the initial years displace T -South capacitythat would then be assigned to other parties or turned back to Westcoast. The economics ofdisplacing T -South with SCPjTC:PL in 2004 are almost equivalent in value and aresummarized on the table below. -rhe benefits of reducing BCGUL requirements at Station#2would be an additional benefit to core customers in addition to adding increased security ofsupply in the portfolio.

Comparison of T -South an(j TCPUSCP ValueDemand basis value profit/(ioss)

T -South $ 6,196,524 $ 4,848,843 $ (1,347,680)

SCPITCPL $ 8,834,249 $ 7,478,432 $ (1,355,817)

The cost details are attached.

Page 14

The net benefits accruing to BC(;UL's customers are shown in the attached proforma fordifferent scenarios. In all scenariios, the transactions between BCGUL, PG&E and NWN areput in place, effectively allowing BCGUL to lock in the value of the long term firmtransportation service agreement with NWN.

In the Base Case (Scenario 1), BC Hydro also remains a SCP transport customer until theend of its renewal rights, October 2019. The base case also assumes IPC does not proceedbefore 2020.

Scenario 2 is a "worst case" scen21rio where BC Hydro puts the SCP capacity back to BCGUL,and BCGUL is only able to partially mitigate the loss of the SCP revenue over the primaryterm. In this scenario, the Inl.3nd Pacific Connector project would not proceed, as themarket does not value the capacity sufficiently. It is expected that BC Hydro would only"put" the capacity if the existing agreements were at a premium to the market. In thiscase, it is unlikely that BC Hydro or PG&E would have renewed the capacity beyond theprimary term, and the total capclcity would have been returned to BCGUL in 2010. Theadded benefit of the NWN contract is that it locks in value until 2020. In this scenario it isassumed that the current forNard market value as described in Attachment 2isrepresentative of the value of the capacity up to 2020.

Scenario 3 is the same case as Scenario 2, except that the mitigation value of the BC Hydrocapacity that is put back to BCGUL is based on the weighted average value estimated inAttachment 2. This scenario is still very conservative as it is using current marketinformation for 2004/05 to value the capacity to 2020.

Scenario 3 is a "best case" sceni3rio where the Inland Pacific Connector project is put inservice 2006, with corresponding increases in revenues from the Inland Pacific Connector.In this scenario, BC Hydro would be expected to keep the value its SCP capacity as it is at adiscount to the expected IPC cost5:.

The results are summarised in thl~ table below. These cashflows are calculated as the netincremental benefits these propolsed arrangements would deliver, relative to a scenariowhere the current arrangements with PG&E and BC Hydro stay in place. Note that inScenarios 1 and 2, BCGI would be seeking to recover its Inland Pacific Connector costs fromthe additional revenues generatE!d by the NWN contract beginning in 2006. The NPVcalculations here assumes that BC:GI would be allowed to recover the full costs.

Net SCP Firm Trans ort Benefitsthousands Scenario 1 Scenario 2 Scenario 3 Scenario 4

Annual Revenues Yl-2 -$2,685 $2,451Annual Revenues Y2-6Annual Revenues Y7-16

$1,125 $2,685$4,382$5,357

$34,700

$2,685$4,000

$2,451$5,248$28.875I NPV CO) 10%

$5.600Recovery of IPC Development Cos1ts $5,600 $5,600 N/AI NPV after IPC Cost Recovery $20,000 $21,900 $22,275

Page 17

.

Attachment 4 -Peaking Replacement effective November2004

BCGUL has completed analysis orl potential peaking option replacement for the SCP peakingarrangements that will be terminated on November 01, 2004. Based on core requirementsthe most economic option appears to be replacement with Mist storage expansion capacity.By contracting Mist expansion capacity BCGUL will be receive a number of long termadvantages compared to the exis1:ing SCP peaking arrangements including:

1. Providing for sponsorship of incremental physical storage capacity into the region.2. Peaking supplies that will on average be at or lower than the cost estimated for the

SCP peaking and providing significant protection from extremely high day prices.3. Added flexibility that storal~e provides on an intra-day basis.4. Added benefits of not affec:ting the day market at Kingsgate or Sumas on call days.5. Ability to contract long term storage capacity (5-15 years) at today's market prices

providing long term cost protection and diversity for core customers.

The table below summarizes the costs of SCP peaking vs Mist storage assuming 5 days ofpeaking requirement in one year. BCGUL has assumed both conservative price volatilitythat excludes the volatility experienced in the winter of 200/01 as well as historical pricevolatility based on the average of the last 5 years. In both cases the SCP peaking is at ahigher cost.

Detailed economic cost assumptions and analysis to support this table are on the following 3tables.

Page 22

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